This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Only a portion of the oil originally present in a subterranean oil-bearing formation is recovered during the primary production cycle of the oil. A significant fraction of the oil-in-place is left in the ground after primary recovery. Water injection, sometimes referred to as waterflooding, and gas injection, sometimes referred to as gas flooding, are used as enhanced oil recovery (EOR) processes to recover the remaining oil. Water and gas are commonly injected alternately in a process referred to as water-alternating-gas (WAG) flooding.
The terms “gas injection” and “gas flooding” typically refer to an oil recovery process in which the fluid injected is a hydrocarbon gas, inert gas, carbon dioxide, acid gas, or steam. Acid gases are gases that contain predominantly carbon dioxide, hydrogen sulfide, or mixtures thereof and which form acidic solutions upon dissolution in water. Carbon dioxide (CO2) and other acid gases are particularly attractive gas injectants because they are able to achieve miscibility with crude oil over a wide range of reservoir conditions. In addition, it is anticipated that the use of carbon dioxide in gas injection EOR will continue to increase in the future as incentives are put in place to store large quantities of carbon dioxide underground to reduce greenhouse gas emissions to the atmosphere. In addition, acid gas is also produced as an undesirable byproduct of oil or gas production from reservoirs containing fluids with concentrations of carbon dioxide and/or hydrogen sulfide. Using acid gas as an EOR injectant is one way to put this waste product to beneficial use.
The success of water and gas floods can be diminished by early breakthrough of the injected water and/or gas at production wells. A particularly serious problem is early breakthrough caused by channeling of the injectant through high-permeability pathways connecting certain injection wells to the “breakthrough” production wells. The pathways may consist of thin high-permeability layers or “thief zones,” networks of higher-permeability rock, or systems of natural or induced fractures. Such channeling, or poor conformance, of the injected fluid can cause it to contact and sweep only a small portion of the reservoir volume, thus limiting the amount of oil recovered, causing inefficient utilization of the injected fluid, and limiting the ultimate storage efficiency of carbon dioxide or other acid gas. Channeling is a particular concern in heterogeneous carbonate formations.
Channeling can be further exacerbated by unfavorable mobility and density ratios between the injected and reservoir fluids, which cause the injected fluid to finger through the resident reservoir fluids and to gravity segregate in the reservoir. Fingering and gravity segregation are particular concerns in gas or WAG injection, because gases have higher mobility and lower density than oil or water.
A variety of remedial actions have been proposed to mitigate channeling problems. The rate of fluid production at the offending production well may be reduced or the well may be shut in periodically to limit production of the injected fluid. If the source injection well for the unwanted production can be identified, the rate of injection at that well can be reduced. Plugging substances such as cements, gels, polymers, foams, or combinations thereof may be placed in the high-permeability pathway to block flow and divert injected fluids into other less permeable regions of the reservoir.
However, the use of such plugging or blocking agents has had limited success in highly heterogeneous formations in which there is a wide range of permeability and the higher permeability portions of the rock are in good hydraulic communication with the lower permeability portions. In such cases, it has been found that although some of the injectant may be diverted into lower permeability rock, it rapidly finds its way back to the higher permeability rock, which provides the path of least resistance to flow. In addition, although the ratio of injectant to oil in the production stream may be temporarily reduced, often the rate of oil production drops as production from the more permeable portions of the formation is shut off.